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Abstract A unique well-tracing design for three horizontally drilled wells is presented utilizing proppant tracers and water- and hydrocarbon-soluble tracers to evaluate multiple completion strategies. Results are combined to present an interpretation of them in the reservoir as a whole, where applicable, as well as on an individual well basis. The new approach consists of tracing the horizontal well(s) leaving unchanged segments along the wellbore to obtain relevant control group results not available otherwise. The application of the tracers throughout each wellbore was designed to mitigate or counterbalance variables out of the controllable completion engineering parameters such as heterogeneity along the wellbores, existing reservoir depletion, intra- and inter-well hydraulically driven interactions (frac hits) as well as to minimize any unloading and production biases. Completion strategies are provided, and all the evaluation methodologies are described in detail to permit readers to replicate the approach. One field case study with five horizontal wells is presented. Three infill wells were drilled between two primary wells of varying ages. All wells are shale oil wells with approximately 7,700 ft lateral sections. The recovery of each tracer is compared between the surfactant treated and untreated segments on each well and totalized to see how the petroleum reservoir system is performing. A complete project economic analysis was performed to determine the viability of a chemical additive (a production enhancement surfactant). Meticulous analysis and interpretation of the proppant image logs were performed to discern the cluster stimulation efficiency during the hydraulic fracturing treatments. Furthermore, comparisons of the cluster stimulation efficiency between the two mesh sizes of proppant pumped are also provided for each of the three new unconventional well completions. The most significant new findings are the surfactant effects on the wells’ production performance, and the impact the engineered perforations with tapered shots along the stages had on the stimulation efficiency. Both the right chemistry for the formation and higher cluster stimulation efficiencies are important because they can lead to increased well oil production. The novelty of this tracing design methodology rests in the ability to generate results with a statistically relevant sample size, therefore, increasing the confidence in the conclusions and course of action in future well completions.
Ramos, Claudio R. (Pro Technics Division of Core Laboratories LP) | Warren, Mark N. (Pro Technics Division of Core Laboratories LP) | Jayakumar, Swathika (Pro Technics Division of Core Laboratories LP)
Abstract The optimistic outlook of the petroleum E&P industry, especially with regard to the re-balancing of oil and natural gas prices, has led to a renewed interest in tight gas and liquids-rich plays, more specifically in the Niobrara and Codell formations in the Denver-Julesburg (DJ) Basin. Through the use of post-stimulation completion diagnostics, insights have been obtained that can be utilized to optimize future hydraulic fracturing completions. Formations with less than one millidarcy permeability require reservoir stimulation in order to economically produce oil and gas. Engineers will often optimize a well's completion, spacing and hydraulic fracturing treatments to maximize its return with respect to cost. This paper will illustrate the use of post-stimulation completion diagnostics in identifying trends that are associated with effective completions in the Niobrara and Codell formations. In addition, case histories will be presented which illustrate methods that have increased the overall completion effectiveness in relation to proppant placement, wellbore deliverability and, ultimately, increased production performance. A horizontal well database (> 350 wells) was compiled to identify effective completion trends across the Niobrara and Codell formations. By employing proppant and fluid-based tracers, hydraulic fracture geometry, well deliverability and production performance were measured to identify trends that increased overall completion effectiveness. Primary completion results highlight areas including, but not limited to, effective proppant placement, full lateral production, frac stage length and containment, perforation cluster/sleeveefficiency, wellbore lateral length and inter-well communication between Niobrara and Codell formations. Many of the insights gained through this use of post-stimulation completion diagnostics in the Niobrara and Codell formations have led to increased completion optimization, production enhancements and field-wide cost reductions.
Abstract This case study helped an operator in the Powder River Basin approach an optimized completion design. The operator used geomechanical measurements, hydraulic fracture modeling, and fracture diagnostics on two horizontal wells. The two wells are near a previously-completed, producing well (i.e., “parent” well). While drilling the two horizontal wells, the operator acquired geomechanics data. This method, called drill bit geomechanics, measured the variability along the laterals. These data produced geomechanically-informed perforation and stage placements to minimize the differences in minimum horizontal stress across each stage. Additionally, the operator engineered the perforation sizes, which increased perforation friction to overcome the measured variability. The authors used the near-wellbore geomechanics data, along with other data, in a hydraulic fracture simulator. In general, standard hydraulic fracture simulators assume constant mechanical properties in each geologic layer. Compared to this standard practice, adding measured geomechanics data can more accurately predict which perforation clusters may be stimulated. To test two different fluid systems, the operator designed a “hybrid” (i.e., combination of slickwater and crosslinked gel) treatment for Well 1 and a slickwater treatment for Well 2. Fracture diagnostics reported their effectiveness. Diagnostics included: 1) proppant tracers to evaluate the perforation efficiency, 2) oil-soluble fluid tracers to quantify by-stage production contribution, and 3) water-soluble fluid tracers to assess inter-well communication. Also, the operator had used proppant tracers on the parent well, providing a baseline for results comparison. Compared to the parent well, the two study wells showed 15-22% higher perforation efficiency. This suggests the engineered design changes created more even proppant distributions. Understanding the geomechanical variability, the operator recognized the engineering required to overcome it. The oil-soluble tracer, although affected by the parent well's depletion profile, showed higher perforation efficiency can increase oil production. Between the two study wells, Well 1 had higher perforation efficiency than Well 2 and it slightly out-produced Well 2. This suggested the hybrid design was likely the more effective design. The hydraulic fracture simulator with near-wellbore geomechanics data predicted perforation efficiency similar to that measured by the proppant tracer. Across both wells’ traced stages, the predicted efficiency and measured efficiency were within 3%. The measurements validated the modeling method. This paper describes a method of improving completion designs through 1) geomechanics data measured while drilling, 2) modeled perforation cluster efficiency, 3) a measurement of proppant placement effectiveness, and 4) an estimate of stage-by-stage production. For the Powder River Basin operator, this method informed decisions about the next completion design iterations. Operators in any unconventional basin could apply this workflow to approach an optimized completion.
Senters, C. W. (ProTechnics Division of Core Laboratories LP) | Leonard, R. S. (ProTechnics Division of Core Laboratories LP) | Ramos, C. R. (ProTechnics Division of Core Laboratories LP) | Wood, T. M. (ProTechnics Division of Core Laboratories LP) | Woodroof, R. A. (ProTechnics Division of Core Laboratories LP)
Abstract Success of a fracture stimulation treatment depends upon complete coverage of all targeted intervals. Diversion techniques are being applied in new well completions to achieve greater cluster treatment efficiency and to access additional rock. The objective of this study is to characterize diversion and to utilize near-wellbore diagnostics to determine the effectiveness of diversion. Multiple basins are included in this study, incorporating a variety of drilling and completion practices. Proppant tracing and temperature logging provide near-wellbore diagnostics to evaluate the new rock contacted as a result of diversion. Tracers injected during the treatment at various intervals before and after diversion can be used to determine cluster efficiency as well as the overall changes to a stage as a result of the diversion. Temperature logging is used to determine cooling effects of the treatment and is correlated back to the near-wellbore proppant coverage. The combination of multiple diagnostics provides additional confirmation of the treatment coverage or in some cases the lack thereof. The results of this study show examples of both effective and ineffective diversion. Effective near-wellbore diversion is defined as diversion that results in accessing clusters that were previously not stimulated or under-stimulated. In many cases the surface treating pressure response due to diversion does not correlate to its effectiveness. Optimizing the design and deployment of the diversion process often results in improvement of treatment effectiveness. The results of this study are grouped by Anadarko Basin, Permian Basin, Eagle Ford, and Williston Basin and show the effectiveness of a variety of diversion techniques. Through a combination of diagnostic techniques, diversion is evaluated on new well completions. Over 30 wells are included in this study across multiple basins. The overall stage coverage is evaluated along with the effectiveness of near-wellbore diversion to achieve this coverage. These learnings can be applied to optimize diversion designs for future wells in these and other basins.
Johnson, M. D. (ProTechnics Division of Core Laboratories) | Pechiney, J. J. (ProTechnics Division of Core Laboratories) | Warren, M. N. (ProTechnics Division of Core Laboratories) | Woodroof, R. A. (ProTechnics Division of Core Laboratories) | Leonard, R. S. (ProTechnics Division of Core Laboratories) | Moore, C. P. (ProTechnics Division of Core Laboratories)
Abstract Horizontal shale gas and oil completion designs have evolved over the last several years. Effective completion design has become extremely important in developing these shale plays. In general, the industry has moved towards longer laterals, more stages, closer spacing between entry points, and increased proppant and fluid volumes. The use of completion diagnostics can be applied to supplement production data and stimulation modeling in optimizing the completion designs and reducing the slope of the learning curve in these emerging shale plays. Fluid and proppant tracer technologies and production profiling have been successfully employed in this optimization process. This paper will present several case histories demonstrating how these completion diagnostic tools have been successfully deployed to assess stimulation effectiveness. Case histories will be presented from the Marcellus, Eagle Ford, Haynesville, and Woodford shales in which these technologies have been employed to characterize proppant placement and load fluid clean-up and to quantify fluid and proppant communication between wells. In these case histories, the diagnostic results were used to evaluate perforation design, fluid and proppant placement as a function of the perforating scheme, lateral coverage, and fluid clean-up as it relates to lateral length, wellbore trajectory, changes in lithology, and frac fluid design. This paper will characterize and validate the role of completion diagnostics in the completion optimization process.